1. Field of the Invention
The field of the present invention is the treatment of high pressure water injection wells. Another aspect of the present invention is concerned with a corrosion inhibitor for use in connection with injection well treatment water, and in particular water which is acidic or which includes chlorine dioxide.
2. Related Art
The oil industry uses a variety of techniques to maximize the recovery of oil from any particular oil formation. One of the methods used is the injection of water under high pressure at a point removed from the site of the oil removal. Large amounts of water are injected under high pressure into the oil-producing sands and are removed at the oil well site along with the resident oil. Such methods typically require up to twenty parts water per part oil recovered. Given this large amount of required water, many oil producers utilize the nearest large source of water,.which can be a surrounding ocean, nearby bay, or water produced with the oil. Little care is taken to purify the injection water and, therefore, a wide variety of impurities are often injected in the water injection well.
The constant high volume flow of impure water and the warm, incubator-like environment of oil field water treatment systems encourages the uncontrolled growth of biomass--the source of many costly problems. Bacterial growth, if left unchecked, causes: formation of hydrogen sulfide, a toxic and corrosive gas that eats through piping in water and vapor recovery systems; accumulation of gummy biomass that adheres to surfaces and filter media and substantially reduces equipment efficiency; formation of abrasive iron sulfide that wears injection pumps, decreases injectivity, fouls flow lines and causes corrosion; all increasing operating costs and lowering oil production. The resultant build-up at the screen leading from the casing into the oil-producing sands constricts the flow of water through the tubing and screen. As the flow is constricted, less water can be pumped through the system, leading to decreased oil production. If the water injection tubing and screen are not cleaned out periodically, the screen can become entirely obstructed.
A commonly accepted procedure for cleaning out such water injection casings is to inject hydrochloric acid into the water injection well. The hydrochloric acid, by keeping, the pH of the system low, solubilizes some of the unwanted materials so that they can be washed out of the water injection well. This method suffers from several problems. First, such mixtures can be highly corrosive and will corrode the water injection well. In addition, such a mixture has little or no effect on any biomass that may have built up. Such biomass is often the primary obstructor. Finally, this method of clean-out is relatively expensive.
Typical aqueous hydrochloric acid solutions include 15% by volume hydrochloric acid or 12% by volume hydrochloric acid and 3% by volume hydrofluoric acid. Although such solutions facilitate the injectivity of injection wells by, reacting with carbonate scales on the well and pipe walls, the solutions are very corrosive to the iron pipes causing etching leading to further degradation. Moreover, once the hydrochloric acid is dissipated in the water flow, hydrogen sulfide from the injection well reappears thereby causing further carbonate scale formation.
To inhibit the corrosive effects of hydrochloric acid and hydrofluoric acid solutions, corrosion inhibitors are typically added to the water flow. Typical inhibitors include quaternary amines and acetylene alcohols, which are admixed with a surfactant in an aqueous solution.
Chlorine dioxide has found its way into limited use in the oil production industry. This material has been recognized for the treatment of oil field produced fluids. Reference is made to Canadian Patent No. 1,207,269, issued July 8, 1986, the disclosure of which is incorporated herein by reference. Reference is also made to Smeck, U.S. Pat. No. 4,077,879, issued Mar. 7, 1978. In these processes, the chlorine dioxide is typically used for surface treatment of oil field produced fluids.
See also, Masschelein, W. J. "Chlorine Dioxide-Chemistry and Environmental Impact of Oxychlorine Compounds", Ann Arbor Science Publishers, Inc. (1979), the disclosure of which is incorporated herein by reference.
Chlorine dioxide is known to be a highly corrosive material. Corrosion of metals due to chlorine dioxide is characterized by severe pitting corrosion. Corrosion of this type can lead to catastrophic failures of metals exposed to this environment.
Therefore, there exists a need for inhibiting corrosion caused by chlorine dioxide and other acids if chlorine dioxide and such acids are used in a process to treat water injection or oil-producing wells.